In 2018, a group of the world’s largest crude oil and natural gas producers added more hydrocarbons to their resource base than in any year since at least 2009, according to the annual reports of 116 exploration and production (E&P) companies. During 2018, these companies collectively added a net 10.3 billion barrels of oil equivalent (BOE) to their proved reserves, which totaled 286 billion BOE at the end of the year. Total exploration and development (E&D) costs incurred in 2018 for these companies increased 4% from 2017 levels, but declined 9% from 2017 when calculated as dollars per BOE of proved reserves added. This analysis is based on published financial reports of these 116 companies and does not necessarily represent the financial situation of private companies that do not publish financial reports.
Of the 116 companies, the top 18 held more than 80% of the 286 billion BOE in proved reserves at the end of 2018. Although many of these companies have global operations, some are national oil companies with reserves and operations concentrated in their home countries including Russia, China, and Brazil. Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production. Figure 1 illustrates the 116 companies’ combined proved reserves changes during 2018.
Organic additions to proved reserves—those added through improved recoveryand extensions and discoveries—are linked directly with expenditures in E&D. Proved reserves acquired through purchases and sales represent transfers of assets between companies (including companies outside this group) but are not reflected in E&D expenditures. Revisions to proved reserves can be highly influenced by changes in crude oil and natural gas prices but less directly influenced by E&D investment.
Of the 21.0 billion BOE in organic proved reserves added in 2018 (that is, before accounting for revisions, net reserves purchased, or how much the companies produced), slightly more than half (10.7 billion BOE) came from the United States, while the Russia, Central Asia, and Asia-Pacific region accounted for 4.0 billion BOE (19%). Canada added 2.1 billion BOE (10%) and Latin America added 1.6 billion BOE (8%). Europe and the Middle East and Africa region each added fewer than 1.0 billion BOE, accounting for about 4% of global organic proved reserves additions each (Figure 2).
Global E&D costs incurred increased for the second consecutive year in 2018, increasing 4% to $319 billion. Of this total, 38% ($122 billion) came from the United States, with the Russia, Central Asia, and Asia Pacific region accounting for 26% ($83 billion) and all other regions accounting for less than 10% each. Changes in nominal year-over-year E&D costs incurred varied across regions, increasing by 33% in Europe, 13% in the United States, and 3% in the Middle East and Africa region. Costs incurred declined by 2% both in the Russia, Central Asia, and Asia Pacific region and Latin America, while spending in Canada was essentially flat compared with 2017 (Figure 3).
Because significant cost deflation has occurred in the oil and natural gas industry since 2014, nominal costs incurred in different years may not be directly comparable. Finding costs provide an indicator of the expenditures needed to add a barrel of proved reserves. Because of the disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years.
Analyzed this way, three-year average costs declined on a per BOE basis in 2016–18 compared with both the 2013–15 and the 2010–12 averages (Figure 4). The three-year average E&D costs incurred per BOE of organic proved reserves additions in 2016–18 were lower than their respective 2013–15 and 2010–12 averages in all regions except Latin America, where the 2016–18 average was slightly higher than its 2010–12 average. On an annual basis, the 2018 E&D costs incurred of $15.20 per additional BOE of proved reserves was the lowest since at least 2009.
For further analysis and a list of the companies included in this study, see EIA’s annual Financial Review. Later this year, EIA will issue its annual U.S. crude oil and natural gas proved reserves report which focuses exclusively on proved reserves located in the United States, including all U.S. producers (publicly traded and privately owned companies).
U.S. average regular gasoline and diesel prices decrease
The U.S. average regular gasoline retail price fell 3 cents from the previous week to $2.82 per gallon on May 27, down 14 cents from the same time last year. The Gulf Coast price fell over 4 cents to $2.47 per gallon, the West Coast price fell nearly 4 cents to $3.63 per gallon, the Midwest price fell 3 cents to $2.71 per gallon, the East Coast price fell nearly 3 cents to $2.70 per gallon, and the Rocky Mountain price fell less than one cent, remaining at $2.98 per gallon.
The U.S. average diesel fuel price fell more than 1 cent to $3.15 per gallon on May 27, 14 cents lower than a year ago. The price in each region fell over one cent. The West Coast price fell to $3.78 per gallon, the Rocky Mountain price fell to $3.18 per gallon, the East Coast price fell to $3.16 per gallon, the Midwest price fell to $3.04 per gallon, and the Gulf Coast price fell to $2.89 per gallon.
Propane/propylene inventories decline slightly
U.S. propane/propylene stocks decreased by 0.1 million barrels last week to 65.8 million barrels as of May 24, 2019, 9.8 million barrels (17.5%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast and East Coast inventories decreased by 0.7 million barrels and 0.5 million barrels, respectively. Midwest and Rocky Mountain/West Coast inventories increased by 0.9 million barrels and 0.3 million barrels, respectively. Propylene non-fuel-use inventories represented 8.0% of total propane/propylene inventories.
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When asked in December about the projected slowdown in American shale output, the new US Energy Secretary shrugged off the notion, describing it as a mere ‘pause’. Blaming the expected slowdown to the ‘natural adjustments’ of oil and gas prices instead of a structural decline in production, Dan Brouilette is painting a rosy picture of US shale – where riches still lie underneath, waiting for the right price to be extracted. Of course he would paint such a picture. Brouilette is the new Energy Secretary, replacing Rick Perry. He couldn’t come in on a message of doom and gloom. But his pretty picture isn’t accurate either.
Schlumberger just posted a US$10 billion loss for the full year 2019, despite relatively flat y-o-y revenues. CEO Oliver Le Peuch called its international performance ‘positive’, but blamed ‘land market weakness’ causing a sharp decline in North American revenues and profits. Land market is code word for shale, and Schlumberger isn’t the only one facing problems. Halliburton announced a loss of US$1.1 billion in 2019, taking a US$2.2 billion charge on weakening US shale activity as North American revenue for Halliburton fell by 21% in 4Q19 and 18% for the whole year. While its results managed to beat analyst predictions – already stung by Schlumberger’s results – Halliburton doesn’t expect things to get rosier either, signalling that it expected ‘customer spending’ in North America to be down again in 2020.
And it isn’t just service companies suffering. US supermajor Chevron booked a US$11 billion write-down on a collection of assets in its latest set of financials, including on a major deepwater project in the Gulf of Mexico, the Kitimat LNG project in Canada and onshore Appalachian shale assets. Taken as a whole, the total impairment might coming from Chevron’s lowered forecast for oil and gas prices to the US$55-60/b range for 2020, but that shale was singled out is a major factor. And Chevron isn’t the only one. BP, Repsol and even ExxonMobil are expecting weakness. Only Shell and Total, who haven’t devoted as much attention to US shale, particularly the Permian, have been relatively insulated.
Why is this happening? There are two different factors operating. From a producers’ standpoint, the rising tide of US shale output is contributing to weakening global prices for oil – and that has a lot to do with the debt burden of existing US shale players, who have to keep drilling to pay off loans. Added conventional production coming online from Guyana, Brazil and Norway at the same time aren’t helping with prices either, despite OPEC+’s best intentions. From a service company’s perspective, firms like Schlumberger and Halliburton derive their revenue from drilling activity, not drilling output. And US drilling activity has dropped steeply over the past year, currently down by over 250 rigs according to the Baker Hughes weekly rig count. Much of this is onshore, principally in the Permian but also in other basins, as the once nimble and dynamic drillers are forced to stop activity either through bankruptcy or to shut shop temporarily as crude prices fall to uneconomical levels.
The US EIA has issued a new forecast, predicting that US shale output will slow down to a 1.1 mmb/d gain over 2020. That’s still optimistic, taking total US production to 13.3 mmb/d. In 2021, however, the EIA think output growth will fall even further, to an annual gain of just 400,000 b/d. Implicit to that forecast is that the EIA expects prices to remain subdued over the new two years, because shale drillers would respond to higher prices with increased drilling. There is also production structure to consider. Shale well produce immediate results, but show steep declines after. From 2012 to 2019, the amount of drilled but uncompleted (DUCs) wells – ie. wells that can be exploited within a short time frame – grew and grew; in the last 9 months, the glut of DUCs has shrunk – suggested that the industry is not drilling new wells as fast as they are completing already-drilled. Drilling activity has declined, and the chronic decline in the Baker Hughes active rig count – 18 of the last 21 weeks showed a net loss of rigs – is just proof of that.
It may not be the picture that Dan Brouilette wants to paint, but it is reality. The shale slowdown is real. It is also true that shale activity would increase if prices rose to more viable levels – say the US$65-70/b range – but let’s be honest, what are the odds of that happening when shale itself is the cause of weakening prices.
Nagman has diversified into dealing with Flow meters or Instruments viz Electro-Magnetic Flow Meters, Coriolis Mass Flow Meter, Positive Displacement Flow Meter, Vortex Flow Meter, Turbine Flow Meter, Ultrasonic Flow Meter.
Electro-Magnetic Flow Meter:
Size : DN 3 to DN 3000 mm
Flow Velocity : 0.5 m/s to 15 m/s
Accuracy : ±0.5%, ±0.2% of Reading
Coriolis Mass Flow Meter:
Size : DN8~DN300
Flow Range : 8 to 2500000 Kg/hr (for liquids)
4 to 2500000 Kg/hr (for gases)
Accuracy : 0.1% 0.2% 0.5% of Normal Flow Range
Positive Displacement Flow Meter:
Size : DN 15 ~ DN 400
Max. Flow Range : 0.3 m3/hr to 1800 m3/hr
(Will vary based on the measured media & temperature)
Accuracy : 0.1% 0.2% 0.5%
Vortex Flow Meter:
Size : DN 25 to DN 300
Flow Range : 1.3 m3/hr to 2000 m3/hr (Water)
8.0 m3/hr to 10000 m3/hr (Air)
Accuracy : ±1.0% of Reading
Turbine Flow Meter:
Size : DN 4 to DN 200
Flow Range : 0.02 m3 /hr to 680 m3 /hr
Accuracy : 1.0% or 0.5% of Rate
Ultrasonic Flow Meter:
Type : Hand held Ultrasonic Flow meter with S2, M2, L2 Sensors
Accuracy : ±1% of Reading at rates > 0.2 mps
Measuring Range : DN 15 – DN 6000
In its Short-Term Energy Outlook (STEO), released on January 14, the U.S. Energy Information Administration (EIA) forecasts that U.S. natural gas exports will exceed natural gas imports by an average 7.3 billion cubic feet per day (Bcf/d) in 2020 (2.0 Bcf/d higher than in 2019) and 8.9 Bcf/d in 2021. Growth in U.S. net exports is led primarily by increases in liquefied natural gas (LNG) exports and pipeline exports to Mexico. Net natural gas exports more than doubled in 2019, compared with 2018, and EIA expects that they will almost double again by 2021 from 2019 levels.
The United States trades natural gas by pipeline with Canada and Mexico and as LNG with dozens of countries. Historically, the United States has imported more natural gas than it exports by pipeline from Canada. In contrast, the United States has been a net exporter of natural gas by pipeline to Mexico. The United States has been a net exporter of LNG since 2016 and delivers LNG to more than 30 countries.
In 2019, growth in demand for U.S. natural gas exports exceeded growth in natural gas consumption in the U.S. electric power sector. Natural gas deliveries to U.S. LNG export facilities and by pipeline to Mexico accounted for 12% of dry natural gas production in 2019. EIA forecasts these deliveries to account for an increasingly larger share through 2021 as new LNG facilities are placed in service and new pipelines in Mexico that connect to U.S. export pipelines begin operations.
Net U.S. natural gas imports from Canada have steadily declined in the past four years as new supplies from Appalachia into the Midwestern states have displaced some pipeline imports from Canada. U.S. pipeline exports to Canada have increased since 2018 when the NEXUS pipeline and Phase 2 of the Rover pipeline entered service. Overall, EIA projects the United States will remain a net natural gas importer from Canada through 2050.
U.S. pipeline exports to Mexico increased following expansions of cross-border pipeline capacity, averaging 5.1 Bcf/d from January through October 2019, 0.5 Bcf/d more than the 2018 annual average, according to EIA’s Natural Gas Monthly. The increase in exports was primarily the result of increased flows on the newly commissioned Sur de Texas–Tuxpan pipeline in Mexico, which transports natural gas from Texas to the southern Mexican state of Veracruz. Several new pipelines in Mexico that were scheduled to come online in 2019 were delayed are expected to enter service in 2020:
U.S. LNG exports averaged 5 Bcf/d in 2019, 2 Bcf/d more than in 2018, as a result of several new facilities that placed their first trains in service. This year, several new liquefaction units (referred to as trains) are scheduled to be placed in service:
In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction capacity to 10.2 Bcf/d (baseload) and 10.8 Bcf/d (peak). EIA expects LNG exports to continue to grow and average 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021, as facilities gradually ramp up to full production.
Source: U.S. Energy Information Administration, Natural Gas Monthly